Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Fourth Quarter 2023 Financial Results Conference Call. My name is Sylvie, and I will be your conference operator today. All lines have been placed on mute to prevent any background noise. If you have any difficulties hearing the conference, please press star zero for the operator's assistance at any time. After the speaker's remarks, there will be a question-and-answer session. As a reminder, this conference call is being broadcast live on the Internet and recorded. I would like to turn the conference call over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight. Thanks, and good morning, everyone. Thank you for joining us today for AltaGas's fourth quarter and full year 2023 financial results conference call. Speaking on the call this morning will be Vern Yu, President and Chief Executive Officer, and James Harbilas, Executive Vice President and Chief Financial Officer. We're also joined here this morning by Randy Toone, Executive Vice President and President of our Midstream business, Blue Jenkins, Executive Vice President and President of our Utilities business, and Jon Morrison, Senior Vice President, Corporate Development and Investor Relations. We'll proceed on the basis that everyone has taken the opportunity to review the press release and our fourth quarter results. This call is being webcast, so I encourage those of you listening on the phone lines to follow along in the supporting slides that can be found on our website. As always, today's prepared remarks will be followed by an analyst question-and-answer period, and I'll remind everyone that we will be available after the call for any follow-up or detailed modeling questions that you might have. As for the structure of the call, we'll start with Vern Yu providing an update on the business and progress on our strategic priorities, followed by James Harbilas providing a more detailed walkthrough of our fourth quarter financial results, our near-term outlook, and 2024 guidance. And then we'll leave plenty of time at the end for Q&A. Before we begin, I'll remind everyone that we will refer to forward-looking information on today's call. This information is subject to certain risks and uncertainties, as outlined in the forward-looking information disclosure on Slide two, and more fully within our public disclosure filings on SEDAR. And with that, I'll now turn the call over to Vern. Thanks, Adam, and good morning, everyone. It's great to be here today to discuss AltaGas's fourth-quarter financial results. I'm gonna start by updating you on our operations and our recent corporate developments. 2023 was a very busy and productive year for AltaGas. We made strong progress on our strategic priorities. We advanced a number of growth projects, we delevered, and we de-risked our commercial operations. All of these actions will drive long-term value creation. I'll start by discussing our 2023 achievements. Then I'll provide an update on our major projects, discuss the outlook for natural gas and LPGs, and then talk about our 2024 strategic priorities. Let's start with Slide 4. We delivered normalized EBITDA of CAD 1.575 billion for the year, which puts us in the upper half of our 2023 EBITDA guidance range. This represents a 2.5% increase year-over-year, despite losing EBITDA with the sale of the Alaskan utility. Excluding this impact, 2023 EBITDA increased by roughly 7% year-over-year. 2023 normalized EPS came in at CAD 1.90 per share, which is slightly below the midpoint of our guidance range, principally due to higher short-term debt costs. Commercially, we made strong progress de-risking the business. In the midstream segment, we grew tolling contracts in our global export business from around 25% at the start of the year to 40% at year-end. This aligns with our long-term strategic goal of growing the take-or-pay, cost-of-service portion of our business mix. We are striving to get to around 90% of AltaGas's total EBITDA under these types of contracts over the next couple of years. We entered a 5-year transportation agreement with CN that supports our growing LPG exports. This agreement provides us with a strong predictability for our existing exports at RIPET and provides cost certainty that will extend to our REEF project as well. We commissioned a new VLGC time charter in December, which made its maiden voyage in the fourth quarter, and we commissioned our third time charter in Q1 of this year. These time charters reduce our total shipping cost to Asia by approximately 25% when compared to standard shipping rates. The vessels remove volatility from our marine shipping costs on a long-term basis. In total, we have 3 time charters operating in 2024, and when combined with our financial hedges and tolling contracts, we have effectively eliminated all of our exposure to Baltic freight in 2024. We also signed an agreement for our fourth time charter in 2023, which is currently under construction and set to be commissioned in the first half of 2026. We significantly strengthened our midstream value chain through the acquisition of the Pipestone assets. This deal supports our long-term strategy and adds complementary assets that strengthen our footprint in the Alberta Montney and provides additional liquids for global exports.... A big highlight for us in 2023 was our joint venture with Vopak to develop the REEF project, where we've become the project's operator. We're actively advancing REEF through commercial, engineering, regulatory, and stakeholder work streams. The completion of all this work will position us to make a final positive FID decision in 2024. REEF allows us to meaningfully grow our global export platform for many years to come. Our utilities business was also very active in 2023. Here, we took meaningful steps to maximize long-term value creation as well. We made significant investments in our network, focused on new customer connections and system modernization. We invested $745 million in 2023, which enhanced our system's safety and reliability, while extending the network to new residential and commercial customers. We closed the sale of our Alaskan utility, which provided more than $1 billion of cash to reduce debt, significantly strengthening our balance sheet. We took active steps on cost management to ensure unnecessary costs were removed from operations, and that will continue to be a focus in 2024. We also made progress on our climate initiatives. Our RNG deal with OPAL Fuels will add RNG into WGL system, providing low carbon fuel for our customers. All of these actions help drive strong shareholder returns. During 2023, AltaGas outperformed our peer group by roughly 22% on a TSR basis. In addition to our ongoing investments in the utilities, we added 2 major midstream projects, which are shown on slide 5. The first is Pipestone II, which is a deep cut sour gas processing plant in the Alberta Montney. We reached a positive FID last December, with 100% of the capacity contracted under long-term take-or-pay contracts. We have spud the acid gas injection well for the facility in February. We will be starting pipeline and facilities construction this spring, and we look forward to adding much-needed gas processing and liquids handling capacity to the region. The second new project is REEF, where we continue to move towards a late Q2 FID decision. With Reef, the most significant gating items relate to, one, commercial agreements for the project. Here, we are in advanced negotiations with producers and users and NGL aggregators. We're seeing very strong commercial interest for long-term tolling arrangements. And two, engineering and procurement, where we are more than 75% complete and expect a final Class 3 cost estimate in the coming months. In parallel, we're also advancing procurement and EPC contracting to definitive terms. We're very excited about both of these projects, which will be very important for midstream and provide long-term earnings and cash flow growth. Let's move to slide 6. Gas utilities are irreplaceable and a key part of the ongoing energy evolution. Demand for natural gas within AltaGas's jurisdiction represents 70% of total household energy consumption. Natural gas accounts for nearly 70% of U.S. household energy demand, yet only represents a third of home energy costs. As such, natural gas is the most cost-effective home energy source. In fact, switching to electricity would increase home energy costs by more than 300% in the U.S. Natural gas is critical in the long term to ensure that we have affordable and reliable energy. Natural gas has been the biggest driver in reducing emissions in the U.S. for the last two decades. It's our job to make sure these realities are understood and to advocate for an energy and evolution that provides safe, reliable, and affordable energy, and to make this energy ever greener for the customers that we serve. Slide 7 shows that the fundamentals for our Canadian midstream business are equally compelling. Although we are in a period of low gas prices due to warm weather across North America and excess drilling in Western Canada before West Coast LNG, the multi-year outlook for natural gas is extremely robust as Canada expands markets to Asia. WCSB natural gas production is poised for significant growth through 2030. West Coast LNG facilities such as LNG Canada and Woodfibre LNG are game changers that brings a structural tailwind for supply. All of this activity will create the need for additional midstream infrastructure across BC and Alberta. At the same time, Asian LPG demand is expected to grow significantly over the next two decades, positioning our global export business as the most economically attractive outlet for growing Western Canadian LPG supply. Turning to slide 8, we are excited about the road ahead and advancing our 2024 priorities. This includes operating under an equity self-funding model, achieving our 4.5x leverage target and operating with strong capital discipline, where we ensure that only the best capital projects go forward. In utilities, our number one objective is to improve returns and close the ROE gap at WGL. We made good strides to date, but the journey continues. The recent regulatory decisions in Maryland and D.C. were mixed for us, so to close the ROE gap, we'll have to be even more vigilant on how we deploy capital and manage our costs. We will also need to continue to be very proactive and timely with our rate filings. We'll continue to work on modernizing our aging infrastructure to reduce leaks and improve system safety and reliability. We will continue to invest in and explore growth opportunities related to climate initiatives, such as RNG and energy efficiency programs. Finally, you'll see us ramp up our advocacy for natural gas and our utilities. Within Midstream, our near-term priorities are clear. First, we need to integrate the Pipestone assets into our system and build Pipestone II on time and on budget. Second, we need to advance REEF to FID, which we are targeting for late Q2. Finally, we need to continue to de-risk the business. We made good progress in 2023 by adding additional take-or-pay contracts, adding more tolling agreements, and systematically hedging our remaining exposure. Our plan is to continue down this road again in 2024. All of these actions will improve our profit margins, reduce our debt balance, and lower our commercial risk profile, collectively improving AltaGas's value proposition. We're excited that all of these actions are in our own control, and our job is to execute on them. With that, I'll turn the call over to James to talk more specifically about Q4 2023 and our 2024 outlook. Thank you, Vern, and good morning, everyone. We are very pleased with our fourth quarter and full year 2023 results and the strong progress that we made on our strategic priorities. We achieved normalized EBITDA of CAD 502 million in the fourth quarter and CAD 1.575 billion for the full year. Consistent with our expectations, and as previously communicated, this landed us firmly in the upper half of our 2023 normalized EBITDA guidance range of CAD 1.5 billion-CAD 1.6 billion. We achieved normalized EPS of CAD 0.76 in the fourth quarter and CAD 1.90 for the full year. This was firmly within, but slightly below the midpoint of our 2023 EPS guidance range of CAD 1.85-CAD 2.05. The main drivers for EPS trailing EBITDA was higher than expected interest rates during the year. Normalized FFO per share was CAD 1.33 for the fourth quarter and CAD 4 for the full year, which was largely in line with our expectations. Digging into our operating segments, we'll start with the Midstream segment, which is shown on slide 9. Normalized EBITDA came in at CAD 182 million for the fourth quarter and CAD 684 million for the full year, representing 12% and 13% year-over-year growth, respectively. The fourth quarter included a strong improvement in the profitability of the global exports business relative to last year, due to stronger Asian to North American LPG prices. In the fourth quarter, we exported approximately 91,000 barrels per day of propane and butane across 15 VLGCs. This included approximately 63,000 barrels per day at RIPET and 28,000 barrels per day at Ferndale. This was a bit lower than we anticipated due to the loading of two ships being delayed in late December, which pushed revenue recognition into early January 2024. As a reminder, our global exports business typically recognizes seasonally lower export volumes during the winter months, driven by two factors. First, and most meaningfully, is the absence of butane that we procure from local Washington refineries in the spring and summer, when butane is not required for summer gasoline spec, but is in the fall and winter. The second is seasonal weather-related logistics impacts. In addition to these seasonal impacts, we had the one delayed ship at RIPET and one delayed ship at Ferndale during the fourth quarter, which negatively impacted volumes by an approximate 11,500 barrels per day during the quarter. During the fourth quarter, waterborne exports across all industries experienced elevated shipping times and costs due to congestion issues in the Panama Canal. However, we were insulated against these higher costs as a result of our Baltic freight hedges and through the use of AltaGas's time charters. In addition, our direct market access to Asia from the West Coast insulates us from the operational and cost challenges experienced by shippers accessing the Panama Canal. The fourth quarter also benefited from AFUDC related to MVP construction activities as forward progress continues on the pipeline. In the fourth quarter, we saw a 3% year-over-year volume increases across our G&P footprint, with Townsend and Harmattan showing the strongest growth, while fractionation and liquids handling volumes were up 9% year-over-year, led by North Pine, Younger, and Harmattan. This volume growth continued to highlight the ramp-up of development activity in Canada, with the Montney being at the center of that growth. AltaGas realized frac spread averaged $23.13 per barrel after transportation costs in the fourth quarter, as most of AltaGas' frac spread exposed volumes were hedged. This was approximately $2 per barrel below the fourth quarter of 2022. As I highlighted on our previous quarterly call, we advanced a number of positive de-risking initiatives within our global exports business in the fourth quarter, including a 5-year transportation agreement with CN and taking delivery of 1 new VLGC time charter, with another following in the first quarter of 2024. These initiatives continue to lock in costs and de-risk our business, which we will continue to focus on going forward. Moving on to utilities on slide 10, we reported normalized EBITDA of CAD 311 million in the fourth quarter of 2023, as compared to CAD 294 million in the fourth quarter of 2022, an increase of 6% year-over-year. On a full year basis, we reported normalized EBITDA of CAD 886 million, representing a 5% decrease year-over-year, with the full year number reflecting the impact of the sale of the Alaska utilities and the outsized asset optimization revenue that we generated at Washington Gas over 2022. Overall, fourth quarter utility results were generally in line with our expectations, but included negative weather impacts in Michigan and the District of Columbia due to unseasonably warm weather. The lost contribution from the Alaska utilities and outsized asset optimization contribution that was present in the fourth quarter of 2022, was more than offset in the fourth quarter of 2023 by strong performance from WGL's retail marketing business, higher revenue from rate base additions from ongoing investments in ARP modernization programs, and the positive impact of the Virginia rate case. At the utilities, we deployed CAD 192 million of invested capital for the fourth quarter and CAD 745 million for the full year in 2023 on behalf of our customers. This included CAD 98 million in the fourth quarter and CAD 420 million for the full year through our various ARP modernization programs. These investments are focused on upgrading the network to improve safety and reliability of our system, while also delivering ancillary benefits of long-term productivity improvements, while balancing customer affordability during this period of higher costs of living. Closing the remaining ROE gap at Washington Gas remains one of our top priorities within our utilities, as highlighted on Slide 11. That will include our continued focus on operating with strong capital, cost, and regulatory discipline. In the corporate and other segment, we reported normalized EBITDA of CAD 9 million compared to a CAD 3 million loss in the fourth quarter of 2022. The stronger results were mainly driven by lower expenses related to employee incentive plans and lower corporate operating and administrative expenses. Turning to Slide 12, we remain focused on continued commercial de-risking within the midstream business. We have made solid progress on securing tolling arrangements on our global exports business over the year, including more than a 50% year-over-year rise in the percentage of tolling. We exited 2023 at approximately 40% of our volumes being under tolling arrangements, which will continue to rise in 2024 as we move towards our long-term goal of 60% tolling across the portfolio. Where we continue to have commodity or spread exposure, we'll continue to actively manage our exposures through a systematic hedging program. Currently, we have 90% of expected 2024 global export volumes, either tolled or financially hedged at an average FEI to North American spread of approximately $18 per barrel. This includes being 99% hedged for the first quarter at approximately $18.50 per barrel. We have also actively managed our costs across the export value chain, with substantially all our 2024 Baltic freight exposure effectively hedged through a combination of time charters, financial hedges, and tolling arrangements. We remain focused on balancing our three pillars of our capital allocation framework, as shared on slide 13, including funding organic growth, providing sustainable and growing returns of capital, and operating with financial strength and demonstrating debt reduction over the course of 2023. This included continued enterprise growth in 2023, which resulted in another 6% increase in our dividend to CAD 1.19 per share in December. As we have said in the past, our strategy is to deliver sustainable annual dividend increases that compound in the years ahead. We target an industry-low payout ratio of 50%-60% of earnings, which has been consistent over the past four years. In terms of debt reduction, we had a strong year for absolute debt reduction in 2023, as shown on slide 14. AltaGas exited 2023 at 5.2x trailing net debt to normalized EBITDA on a run rate basis. After adjusting for the Pipestone acquisition debt incurred at year-end, without the corresponding EBITDA being added due to the closing date. This represented approximately CAD 1 billion lower year-end net debt. Turning to Slide 15, we are pleased with the strong progress that has been made on the Mountain Valley Pipeline over the past few months. As we have said in the past, maximizing the value of that investment remains the quickest path for near-term leverage reduction. At this stage, the pipeline is now 99% complete, including 97% of water crossings that remained at the time of construction, resuming in August of 2023, now being complete. 95% of upland pipe welds have also been complete, as has greater than 75% of the crossing of the Appalachian Trail, with hydrostatic testing completed on more than half the pipeline. The in-service date has been shifted from the end of the first quarter 2024 to the end of the second quarter. Moving along to the 2024 capital budget on slide 16, we continue to take a prudent approach to our investment portfolio. As we outlined at our Investor Day in December, we expected to deploy CAD 1.2 billion of CapEx in 2024, which will advance key growth initiatives in our midstream and utilities platform. There have been no major changes to this spending plan to date. The 2024 guidance puts and takes are outlined on slide 17. Overall, we remain well-positioned to achieve our 2024 guidance ranges of normalized EPS of CAD 2.05-CAD 2.25, and normalized EBITDA of CAD 1.675 billion-CAD 1.775 billion. This represents 13% and 9% year-over-year growth, respectively. With that said, we have experienced slightly more headwinds than tailwinds at this point in the year, as outlined on this slide. Overall, we are pleased with the fourth quarter and full year 2023 results, and we believe we have a compelling forward value proposition, as outlined on slide 18. As has been the case over the past four years, we believe execution of our long-term strategic plan will continue to drive outsized shareholder returns in the years ahead. Long-term fundamentals for our business remain strong. Canadian producers are poised to deliver significant growth in natural gas and associated NGL production over the balance of the decade, and AltaGas will play a critical role in providing additional West Coast egress to ensure our North American customers receive the strongest netbacks for their LPGs in the premium Asian markets. Our utilities also have a bright future, with natural gas being a critical fuel for everyday life across our jurisdictions. It will be essential to balance the needs of energy affordability, energy reliability, and the pursuit of climate goals. We remain tremendously excited about the opportunity in front of us, and we are confident that we can deliver. With that, I will turn it over to the operator for the Q&A session. Thank you. Ladies and gentlemen, we will now conduct the analyst question-and-answer session. If you would like to ask a question, press star, then number one on your telephone keypad, and if you would like to withdraw your question, press star, then number two. There may be a brief pause while we compile the Q&A roster. The first question will be from Jeremy Tonet at JP Morgan. Please go ahead. Hi, good morning. Hi, Jeremy. Hi. Just wanted to start off with the LPG exports, if I could. Thanks for the incremental color there. Just wanted to see, I guess, you know, anything else you can share with regards to, you know, the outlook for increasing the percentage, tolling kind of on a, a longer duration, and, and how you think about, I guess, trade-off between duration of take or pay, you know, firm tolling, you know, versus, versus rates charged and, you know, how the current spread, may or may not influence that. Just wondering, you know, over what period of time, could we see that tolling number increase, and where do you see it getting to? Okay, Jeremy, that's a great question. I think, obviously we've made a concerted effort to increase the amount of tolling that we have in our portfolio. Really, if you look at the aggregate EBITDA of AltaGas as a whole, the take or pay cost of service percentage of the EBITDA is about 80% today. Our goal is kind of to get tolling to about 60% of the total, volumes we have, once REEF is up and running. And that, by doing that, we'll drive our cost of service EBITDA mix closer to 90%. So I think we're gonna materially then de-risk the business. Obviously, there's trade-offs. The more tolling you do, you do give up some upside on the merchant barrel, but obviously, that's beneficial to us in the sense that it reduces the earnings and cash flow volatility we see in the business. So, in whole, we're comfortable making that trade of giving up a little bit of the upside for more stability of cash flow. And obviously, we're targeting term as we make more and more—as we get more and more of these tolling agreements. Got it. That's helpful. Thank you for that. And just want to pivot towards the balance sheet, if I could, deleveraging trajectory, and primarily as it relates to MVP as we approach the finish line here. And just wondering, you know, what high-level thoughts you're able to share, I guess, on the possibility of monetizing that asset. Do you still see the type of demand for those type of assets as in the past? Does the asset being kind of captive to Transco, you know, at the end, kind of influence the valuation? Just any high-level thoughts you could share would be helpful. Thanks. Yeah, Jeremy, it's James here. And look, our views haven't changed. We've been pretty consistent that we will see a monetization opportunity for this asset once it becomes operational. And obviously the COD date now is Q2 of 2024. So we would be looking to do price discovery potentially post that COD date. In terms of the pipeline itself, we feel strongly that it still has some very strong attributes from a valuation standpoint, in terms of the 20-year take-or-pay contracts, strong free cash flow generation, obviously low CapEx, the EBITDA growth potential on the Mainline and obviously Southgate could be another expansion with respect to the pipeline. And given the recent transaction that was announced with TC Energy and their PNGTS system, we think there's a lot of read-throughs relative to that valuation to, to MVP, just given the contracted nature of that pipeline and, and, and its free cash flow generation. So we do think that there's some strong demand for these type of infrastructure assets, and, and that was reinforced by that recent transaction that was just announced. Got it. That's helpful. I'll leave it there. Thanks. Thanks, Jeremy. Next question will be from Linda Ezergailis at TD Cowen. Please go ahead. Thank you. With some puts and takes in your outlook for this year, recognizing that there's some tailwinds and headwinds, can you comment on where you see your debt to EBITDA at the end of 2024, if the year substantially unfolds as you've contemplated? Yeah, Linda, it's James here, and I'll answer the question two ways, I guess. If we close an MVP transaction in 2024, then we do believe that we can get to 4.5-4.6x net debt to EBITDA, just given the midpoint of our guidance range. Obviously, if a close or a transaction gets delayed and pushed into 2025, potentially, we do still think that we can get some natural deleveraging from the 5.2x as equity earnings start to be generated within MVP, and we start to include those in our actual results. And we get a little bit of a working capital unwind, as we did see working capital build a little bit as we closed out 2023. That's helpful. Thank you. Just as a follow-up, how would you plan to finance REEF through construction and then permanently? And would the rating agencies have some forbearance to any pressure that might put on your credit metrics during construction? You know, REEF is a project that we've had included in our long-term forecast with the rating agencies for quite some time. So the metrics that we've shared with them and the construction profile and cash flows that we anticipate from REEF once it comes online is something that they're comfortable with in the context of our current ratings. So we wouldn't expect it to put any type of ratings pressure on us as a result of that. Okay. Remember, Linda, we have a JV partner, and the construction cycle will be spread out over a number of years, so it shouldn't be that huge a drag on our funding capacity. Okay, thank you. And just another follow-up on REEF. If there is some slippage in schedule and you can't get to FID in Q2, do you think that would be more related to project financing on the commercial side or EPC? Or, I guess if there is any slippage in timing on any of those fronts, are there any sort of sunset clauses in any of your agreements that might require an FID to be made by a certain date for the project to be viable? Well, I think, Linda, we're very happy with the progress that we're making towards FID on REEF. Really, the two critical gating items are, firstly, getting our arms around the capital cost, and I think as we said in the prepared remarks, we're finalizing the FID. We want to have a very strong class 3 cost estimate before we take an FID decision. And part of that will be ensuring that we have clear line of sight on getting some fixed price EPC contracts for the component parts of the project, as well as having done some really good geotechnical work on the site. And in fact, we've started clearing the site to help us out with that. So I don't see any showstopper in front of us. The other second thing is to get a bunch of tolling contracts finalized as we proceed to FID, and we're seeing very significant interest from producers, end users, and NGL aggregators. So, we're well advanced with commercial discussions on that front. So at the end of the day, we don't see slippage there, and I think you made a comment about project financing. It's not our expectation to project finance this project. Thank you. Thank you. Next question will be from Rob Hope at Scotiabank. Please go ahead. Hello, everyone. I want to go back to slide 11, which is sort of the ROE walk up at WGL. You know, it does look like it's changed a little bit since what you presented at Investor Day, specifically a little bit more potential uplift from rate cases. But just given the recent experiences that you've seen in your rate cases, you know, how do you. You know, how do you move forward in terms of ensuring that you get a timely recovery on your capital? And, you know, could we see you go back a little bit quicker on certain jurisdictions there? I think I'll start here, then I'll turn it over to Blue, Rob. Our expectation is that we need to close this gap, and there's a whole bunch of levers for us to do that. How we spend capital, how we manage our O&M costs, and obviously on how timely we get back into a rate proceeding. It is our expectation that we'll be back in D.C. and Maryland sometime this year. The exact timing is still a bit uncertain. And I think one of the things Blue's team is making progress on is getting more certainty out of D.C. on the timeliness of getting decisions back. But with that, turn it over to Blue. Yeah, thanks, thanks, Vern. Rob, good question. Vern hit the highlights for sure. We continue to focus on minimizing the amount of capital that we have regulatory lag. That does suggest, as Vern said, that we would be filing in both D.C. and Maryland this year. TBD on the exact timing, as he said. You know, I would suggest, as Vern alluded to, the order out of D.C., we thought was pretty good overall, it just took a long time. We're happy with the commission's response in issuing an NOI. We're hopeful that moves to effectively a NOPR to put some timeline and some clarity around from filing to outcomes, and we're optimistic, based on how the commission's moving, that we'll get there. The conversation in Maryland is similar. We're understanding, you know, where they're headed as a commission, understanding what that means for our capital decisions. We clearly have a capital plan outlaid that is focused on ensuring safety and reliability and modernizing our system for lower carbon fuels, as well as continuing to serve our customers with high reli-- you know, highly reliable and affordable energy. But we'll need to think about, as we look across our jurisdictions, how we, how we manage the capital across those jurisdictions based on the timeliness and the lag that does result from that. So all of those things are factors, and of course, our cost discipline, we continue to be focused on. We've been under the run rate of inflation in the last several years. We think we can continue to do that and even improve that, and so that's a lever that we're focused on as well to close that gap. All right, thanks for that. And then maybe just shifting over to the midstream business. So beyond Pipestone, beyond REEF, you know, those other medium-term growth expected projects that you had previously identified. You know, how are discussions going on there, you know, as we inch closer to LNG Canada, as well as, you know, there are a couple other big demand centers for NGLs in Western Canada that are popping up? Well, I think it's. There's lots of commercial interest, Rob. Obviously, our assets in Northeast BC are in the ground already or on the ground already and, like, readily expandable. So we're seeing interest from producers to bring more volumes into North Pine. post-Pipestone II, I think we're out there today talking with customers about Pipestone III. So all those things are working away, and I think we're pretty bullish on potential prospects there. Thank you. Thank you. Next question will be from Patrick Kenny at National Bank. Please go ahead. Thank you. Good morning, guys. Maybe just back to the tailwinds and headwinds for the year. And as you mentioned, producers still gearing up here for LNG Canada. But, you know, recently we've seen some of your key customers in the Montney, recalibrate their capital programs, at least for this year, just in light of where forward gas prices are through the summer. So just wondering, you know, how you see these near-term speed bumps in producer spending, perhaps impacting your, your G&P throughput or your LPG export volume expectations for the year, if at all, and if you see any material risk to your financial guidance as well. Yeah, Pat, it's James here. We don't see any near-term risk to the financial guidance. I mean, obviously within the Northeastern BC footprint that we have in the Montney, we still have a lot of room to go here before people even fill take or pay commitments. So we do experience a lot of stability as a result of that within that footprint. Within the Alberta Montney, we don't expect any short-term headwinds either. And obviously, with key egress projects coming online off the West Coast of Canada, we do think that this is a bit of a blip here in terms of soft gas prices and a mild winter that led to some of the CapEx cuts that you're referring to. But with respect to our guidance, we don't expect any downward pressure here as a result of that. Okay, that's great. Thanks for that. And then maybe just with respect to your outlook, kind of below the EBITDA line, specifically your, your effective tax rate of 21%. Curious just to get your thoughts on how well protected you might be, at least from a cash tax perspective, you know, should we see an increase to Canadian corporate tax rates, with the federal budget next month? And then also, if you had any insights into whether or not the merchant side of your LPG exports business might be protected somehow as well from, you know, any sort of one-time tax targeting, you know, windfall profits from the energy sector? Yeah, I mean, in terms of cash taxes for, for the balance of this year, and, and even if we look beyond this year, we do have, NOLs, obviously, that, that limit the amount of cash taxes that we pay. The only cash taxes that we're currently paying is, on Part VI.1 dividends with respect to prefs, just given our non-operating losses. You know, we don't expect any kind of impact from windfall tax, that we're currently tracking either with respect to exports. And, in terms of the volatility of those cash flows, you know, we've highlighted a couple of times now that we're extremely well hedged at 90% with, with a big chunk of that coming from, an increase in year-over-year tolling percentages. You got it. That's perfect. Thanks, James. Thank you. Next question will be from Robert Catellier at CIBC Capital Markets. Please go ahead. Hi, good morning. I was hoping you could provide a little bit more color on the situation in the Panama Canal, how severe that vessel traffic restriction is, and what impact you see in terms of volumes and, and duration of that those restrictions, and you know, how that might impact versus guidance or a normal year? I think, in Q4, the Panama Canal's restrictions were obviously very significant with the low water levels and so forth. And you saw, FEI to Mont Belvieu spreads widen, but you also saw Baltic freight rates go up. I think we've seen some of that normalize out in Q1. I don't think it's gonna have a major impact on our outlook, though, for 2024, as James had mentioned, that we're highly tolled or hedged this year, so, but long term, I think the Canadian advantage or the West Coast advantage that we have from our export terminals will be sustained because of the just because of the logistical advantage that we have in getting LPGs to Asia from the West Coast. Okay. That's helpful. And then, just on the Blair, the extended outage there, what was the nature of the outage, and was it a planned or an unplanned outage? And what are you seeing in terms of how long before it returns to service? Hey, Rob, it's James here. Obviously, it was a scheduled turnaround for that facility that we had in January. As with any scheduled turnaround, once the operation folks get in there and do their inspections, they saw a couple of areas that we wanted to do some preventative maintenance on. And obviously, the parts for that preventative maintenance took a little time to arrive, and that's what extended the outage beyond what we anticipated. The outage is almost complete, or the turnaround is almost complete, and the outage will be over next week. The plant is expected to be operational again next week as they do their final commissioning. So it was really just us trying to address some preventative maintenance issues within the facility, so that we don't have to take another outage later in the year and go back in there and do that maintenance. Right. It's a normal course for a turnaround. Uh, correct. Just last question for me. I'm just curious how you're looking at potentially handling two growth projects at the same time? Like, how you're set up from a capacity point of view to handle that. Maybe you could speak to how you're managing risk in general. I know there's EPC contracts involved. Maybe you can discuss the percentage EPC expect to have with REEF and just generally your internal operating capacity to handle two projects of that nature at once. Sure. Why, why don't I start on that? I think that's an obvious point of interest because we've seen infrastructure projects go over budget all through the midstream sector. So we're very mindful of how we're managing our capital cost risk. So maybe starting with Pipestone, I think we talked about this a whole bunch at the Investor Day, where effectively it's a plant on-site. The vast, vast majority of the capital is going to be under a fixed-price EPC contract. I think we're 75% protected there. The balance of the work is kinda geotechnical or earthworks driven, and a lot of the component parts are obviously getting built and brought in, so there's not a ton of construction on the site, and it's a single site as opposed to a long linear project, where the industry has seen the biggest capital cost variances. REEF, in many respects, is similar. It is a one specific site. Almost we're trying to get the vast majority, again here, of the component parts built off-site and brought in. That includes the NGL storage vessels, the NGL bullets, the compression, and all those great things. Really, the only significant piece of work that has to be done on-site is the construction of the new dock. And the good news is that the vast majority of the rail loop is already, already exists, so that again, we're minimizing the amount of site construction. So we have staffed up internally to manage these risks, but we do obviously have experience in building processing plants as well as ship loading facilities with, with RIPET. So I think we're cautiously optimistic that we're going to be able to manage these capital costs in a good way. Okay, perfect. Thank you. Thank you. Next question will be from Ben Pham at BMO. Please go ahead. Hi. Thanks. Good morning. I have a couple of questions on, you know, first off, on, MVP. I'm wondering if you can comment. I mean, it's been no secret that you view this as non-core. Have you been receiving inbound calls on it? And then I'm also curious, why haven't you started a formal process with the project 99% done? Hey, Ben, it's James here. I mean, look, we've been pretty consistent about the fact that we've gotten calls throughout our ownership of MVP, even in past years. And the reason that we haven't really kicked off a process is we'd like to see the project operational, because we feel that that's the best way to completely de-risk it and not have kind of any kind of valuation overhang. I mean, obviously, the Q1 in service date slipped. If we had kicked off a process and that process was live, and you get a slippage in the pipeline and some upward cost pressure, even though our interest is insulated from that, you know, we do feel that that could have real valuation implications for a potential buyer. So we've been pretty consistent about being patient here so that we can completely de-risk it and eliminate that kind of overhang. And once the pipeline is flowing gas, then there's certainty there from a buyer's perspective, and there's also more certainty there from us advancing some of the growth projects that we see on the Mainline and the expansion, the Southgate expansion. So that's why we've been pretty patient with this and haven't really launched the process yet. Okay. And can you comment then, since Investor Day, you're feeling better about the valuation and just your comments around conversations with folks into this, that when you do launch the process, it may be a bit quicker process than maybe present transactions out there? Yeah, I think the one transaction that I pointed to in my earlier comments has some very positive read-throughs to MVP. The PNGTS system that was sold had 16-year contract durations. MVP is a little longer than that. The investment-grade counterparty mix that we understand is stronger at MVP relative to that pipeline. And obviously, we do have the expansion opportunities within Southgate and on the Mainline that I think are gonna be really attractive from a growth standpoint. So I do think from a valuation standpoint, it will attract a strong valuation, given those attributes. And we think that the same type of buyers that looked at this pipeline would be interested in MVP as well. Okay. And can I, can I ask then, lastly, on the, the contract or the tolls on the LPG export you said a year on. Can you comment on the composition of the counterparties between suppliers, aggregators, buyers, and where, where do you see that composition moving to or going to when you start to add more? Well, we have got a great mix of producers, end users, and aggregators. I think as we, as production grows in the basin over the next couple of years, you're gonna see growth from all of those counterparties. I think we've talked a little bit about expanding our end user universe with our demethanization process at RIPET, so that's something that we're looking forward to as well. So I think it's gonna be a good mix as we go forward, Ben. There's, it's quite exciting about how much commercial interest there is out there these days. Okay. Thank you. Thank you. The last question comes from Robert Kwan at RBC. Please go ahead. Good morning. If I can then just start with the export business, and first, just on the tolling of it. If I can just make sure I understand the numbers here. So if you're looking to be 60% across the entire piece, and you exited 2023 at 40%, so that implies maybe needing another 20,000-25,000 on existing. And then on REEF, you're looking probably somewhere 30,000-35,000 a day. So is it fair that you're out there looking for about 50,000-60,000 barrels a day of contracting? I think for 2024, we have in our guidance about 115,000 barrels a day of exports for the year. Our expectation is to be at least 50% tolled, perhaps a little bit higher on that. So obviously, to move to 60%, we do need some more tolling on those underlying volumes. The REEF expansion is 55,000 barrels a day. And so if we do 60% of that, that's my math, just the back of the envelope math, gives me something around 40,000 barrels of incremental tolling we need to do, and we have clear line of sight to that, Robert. There's lots and lots of commercial interest. Perfect. I think previously you mentioned you're in discussions for more than double the amount you're looking for. Is that still about the same? Oh, yeah, we, we have line of potential if we're successful on all of the new commercial negotiations. We have to go higher than the 60% number, for sure. Okay. And then if I can just finish, just we've seen some on the utility side. So we've seen some strong asset sale valuations for LDCs recently, and just what are your thoughts on, on what you're seeing out there in the market, and what does that mean or not mean, for your strategy going forward? Well, I think our strategy, as you know, is multi-pronged. We need to improve the returns on our existing businesses. We need to de-risk commercially and delever the balance sheet. Obviously, MVP is the clearest and most fastest way for us to do that. We see great embedded growth, obviously, in midstream and in our utilities, including SEMCO, where we have some very significant growth projects in front of us, and we see the ability to invest about CAD 800 million a year in utilities ratably at attractive returns. So right now, we don't really need to do anything, acquisition or divestiture side outside of MVP to meet our strategic outlook, which is, I feel very robust. We'll always look at things and if there's something that's extremely compelling, then we'll for sure have a hard look at it, Robert. Okay. That's great. Thank you very much. Thank you. This concludes the Q&A portion of the call today. I will now turn the conference back to Mr. McKnight. Thanks, Sylvie, and thank you, everyone, once again for joining our call today and for your interest in AltaGas. That concludes our call this morning. I hope you enjoy the rest of your day, and you have a great weekend. You may now disconnect your phone lines.